1. Field of the Invention
The present invention relates to methods and apparatus for increasing drilling capacity and/or removing cuttings from a deviated wellbore when drilling with coiled tubing.
2. Description of the Related Art
Historically, oil and gas were produced from subsurface formations by drilling a substantially vertical borehole from a surface location above the formation to the desired hydrocarbon zone at some depth below the surface. Modern drilling technology and techniques allow for the drilling of boreholes that deviate from vertical. In particular, deviated or horizontal wellbores may be drilled from a convenient surface location to the desired hydrocarbon zone. It is also common to drill “sidetrack” boreholes within existing wellbores to access other hydrocarbon formations.
During such drilling operations, it may be economically infeasible to use jointed drill pipe as the drill string or work string. Therefore, tools and methods have been developed for drilling boreholes using coiled tubing, which is a single length of continuous, unjointed tubing spooled onto a reel for storage in sufficient quantities to exceed the length of the borehole. Although the coiled tubing may be metal coiled tubing, preferably the coiled tubing is composite coiled tubing. An exemplary composite coiled tubing drilling operation is depicted in FIG. 1 comprising a coiled tubing system 100 on the surface 10 and a drilling assembly, also called a bottomhole assembly 200 (BHA), drilling a subsurface deviated wellbore 170. The coiled tubing system 100 includes a power supply 110, a surface processor 120, and a coiled tubing spool 130. An injector head unit 140 on the wellhead 134 feeds and directs the coiled tubing 150 from the spool 130 into the well 160. The power supply 110 is connected by electrical conduits 112, 114 to electrical conduits disposed in the wall of the composite coiled tubing 150. Further, the surface processor 120 includes data transmission conduits 122, 124 connected to data transmission conduits also housed in the wall of the composite coiled tubing 150. It should be appreciated that metal coiled tubing with conductors extending interiorly or exteriorly of the work string may also be used. See U.S. Pat. No. 6,296,066 and U.S. patent application Ser. No. 09/911,963 filed Jul. 23, 2001 and entitled “Well System”, both hereby incorporated herein by reference. One or more surface pumps 132 are connected to the coiled tubing string 150 and wellhead 134 to supply drilling fluids during operation.
The BHA 200, which includes a drilling motor 205 and a drill bit 210, connects to the lower end of the coiled tubing 150 and extends into the deviated borehole 170 being drilled. Since coiled tubing 150 does not rotate in the wellbore 170, the drilling motor 205 drives the drill bit 210, which drills into the formation 173 forming a wellbore wall 175 and creating cuttings 180. The drilling motor 205 is powered by drilling fluid 176 pumped from the surface 10 through the coiled tubing 150. The drilling fluid 176 flows through the drilling motor 205, out through nozzles 212 in the drill bit 210, and into the wellbore annulus 165 that is formed between the coiled tubing 150 and the wall 175 of the deviated wellbore 170 back up to the surface 10.
When using drill pipe that rotates during the drilling process, cuttings 180 do not tend to accumulate in the annulus 165 of the wellbore 170. In such rotary drilling operations, the rotation of the pipe working against the cuttings 180 tends to stir up the cuttings 180 so that they are more easily carried away by the drilling fluid as it flows through the wellbore annulus 165 to the surface 10. However, when drilling with coiled tubing 150, which does not rotate, the cuttings 180 tend to accumulate in the wellbore annulus 165 whenever the wellbore 170 deviates from vertical by approximately fifteen degrees (15°) or more. In particular, the cuttings 180 accumulate on the low side 172 of the wellbore 170 as shown in cross section in FIG. 2, which is taken along section line A—A of FIG. 1. As the wellbore 170 is drilled, the cuttings beds 180 continue to grow along and around the coiled tubing 150. If not removed, these cuttings 180 will cause the coiled tubing 150 and/or BHA 200 to become buried and get stuck.
One method for removing cuttings 180 from a deviated wellbore 170 is to periodically perform wiper trips. To conduct a wiper trip, drilling is halted, and the coiled tubing 150 is pulled to drag the BHA 200 through the previously drilled wellbore 170 to stir up the cuttings 180 while continuing to circulate drilling fluid so that the drilling fluid can carry those cuttings 180 back to the surface 10. Wiper trips are undesirable because they consume valuable drilling time and can cause damage to the components of the BHA 200, such as the drill bit 210.
Another method for removing cuttings from a deviated wellbore without using wiper trips comprises increasing the flow rate in the wellbore annulus 165 to provide a fluid velocity sufficient to lift the cuttings 180 off lower side 172 of borehole wall 175 and carry them back to the surface 10. Referring again to FIG. 1, during a typical drilling operation, drilling fluid flows through the flow bore 322 of the coiled tubing 150 and through the BHA 200 along path 155 to power the drilling motor 205 and drill bit 210. After exiting the drill bit 210, the drilling fluid flows back to the surface 10 along path 185 through the wellbore annulus 165. As the drilling fluid 176 flows along path 185, it must have a minimum velocity in the annulus to lift the cuttings 180 that accumulate in the wellbore annulus 165 and carry them back to the surface 10. This minimum annulus velocity will vary, as for example, with borehole inclination, size of the cuttings 180, geometry of the deviated borehole 170, and drilling fluid properties.
However, there are several factors that restrict the maximum flow rate. These factors include preventing erosion or abrasion of the coiled tubing 150 or the internal components of the BHA 200, preventing erosion of the wellbore wall 175, not exceeding the maximum flow rate capacity of the downhole motor 205, and not exceeding the maximum collapse and burst pressure ratings of the coiled tubing 150. Accordingly, the maximum flow rate of the drilling fluid 176 flowing along path 155 through the BHA 200 is limited by operational considerations. If this maximum operational flow rate does not provide at least the minimum annulus flow velocity required to carry the cuttings 180 to the surface 10, the cuttings 180 will accumulate in the wellbore annulus 165.
U.S. Pat. No. 5,984,011 to Misselbrook et al., hereby incorporated herein by reference for all purposes, discloses one method of diverting flow into the wellbore upstream of the drill motor. The method comprises ceasing drilling, pumping fluid into the drill string at a critical level of flow that exceeds the drilling flow rate, and valving at least a portion of the fluid to bypass the drilling motor and sweep out any cuttings that have accumulated in the borehole. Misselbrook teaches that the critical velocity is in the range of 3-5 feet/second in order to keep all cuttings suspended in the drilling fluid. Misselbrook also teaches that drilling is ceased so that additional cuttings are not generated while removing the existing cuttings from the wellbore.
U.S. Pat. No. 5,979,572 to Boyd et al., hereby incorporated herein by reference for all purposes, discloses another bypass valving apparatus. Boyd teaches that, except during drilling, it is desirable to suspend operation of the drill motor to prolong its useful operating life. Therefore, the by-pass valving arrangement is positioned upstream of the motor so that fluid may be circulated into the wellbore while by-passing the drilling equipment. According to Boyd, the bypass valving apparatus allows for increased mud flow rates during circulating operations, thereby increasing the removal efficiency of the cuttings, while also increasing the motor life since not all of the mud flowing at the higher circulating rates must pass through the motor.
These apparatus and methods therefore eliminate the need for wiper trips, but each recommends disrupting drilling to sweep the borehole clean of cuttings. Further, even if drilling progresses when fluid is diverted to the wellbore annulus for cuttings removal, it is difficult to achieve an adequate fluid velocity in the wellbore annulus 165 to sweep cuttings to the surface 10 without starving the drill motor 205. Thus, it would be desirable to provide an effective cuttings removal apparatus and method that does not disrupt drilling or reduce drilling efficiency.
The present invention overcomes the deficiencies of the prior art.